July 2004 ECN-C--04-011
DISPOWER
A socio-economic analysis of technical solutions and practices
for the integration of distributed generation
M. ten Donkelaar M.J.J. Scheepers
Acknowledgement
This report is the result of a study provided within Work Package 3 (Socio-economic studies) of the DISPOWER project. The DISPOWER project is undertaken by a consortium of 38 organisations (utilities, power industry, service companies, research centres and universities) from 11 European countries to develop new concepts, strategies and tools that will help to increase the penetration of electricity from renewable energy sources (RES) and distributed generation (DG) in the European energy supply. The European Commission under the 5th Framework Programme supports this research project (Contract No. ENK5-CT-2001-00522). For more information see: www.dispower.org.
The study is conducted by ECN Policy Studies and is registered under project number 7.7397. Authors are grateful to the following experts/organisations for their input on the questionnaire developed for this study: Anastasia Krusteva, Technical University Sofia, Bulgaria - Antonio Buonarota, CESI, Italy -Arie Veltman, ECN Fossil Fuels, The Netherlands - Bernardo Mingo Villalobos, Iberinco, Spain - Carlos Madina, Labein, Spain - Christine Schwaegerl, Siemens, Germany - Colin Foote, University of Strathclyde, United Kingdom - Denis Levebvre, Vergnet, France - Günther Arnold, ISET, University of Kassel, Germany - Hubert Reisinger, Verbund-plan, Austria - Irena Wasiak, Technical University Lodz, Poland - Jan Pierik, ECN Wind En-ergy, The Netherlands - Jens Matics, University of Duisburg, Germany - John Eli Nielsen, Eltra, Denmark - John Hickey, ESB International, Ireland - Juan Sancinena, AIZabala, Spain - Juncal Ferrero Saiz, Iberdrola, Spain - Malcolm Irving, Brunel University, United Kingdom - Michel Dussart, Electrabel/Laborelec, Belgium - Rainer Bitsch, Technical University Cottbus, Germany - René Kamphuis, ECN DEGO, The Netherlands - Stefka Nedeltcheva, NAIS Sofia, Bulgaria.
Abstract
This report analyses the socio-economic impacts of technical solutions and approaches that are being developed for the integration of distributed generation (DG) in electricity distribution sys-tems. For this analysis an inventory was made of technical options, solutions and approaches on the basis of a questionnaire that has been distributed among DG (technical) experts. The ques-tionnaire was not meant to give an exhaustive overview, but to gain insight in the possible tech-nical solutions, options and approaches and the economic interactions between different actors in the electricity market. The different technical options and solutions have been divided into four main categories. Four technologies, one of each category, have been studied in more detail to analyse their impact on the financial relationships between the actors in the distribution net-work. The four technologies are:
• wind power prediction tool (planning tool), • grid control unit (power quality device),
• power operation and power quality management system (ICT device), • power storage device.
To assess the impact of the investments in the proposed technologies on all actors involved (and different from the actor investing), an assessment tool has been developed to qualitatively iden-tify the economic impacts of a number of these options. This assessment tool takes into account the financial transactions between the parties on the distribution network. The analysis also dis-cusses the allocation of the economic value of certain benefits through contracts and economic network regulation.
CONTENTS
LIST OF TABLES 5 LIST OF FIGURES 6 ABBREVIATIONS 7 EXECUTIVE SUMMARY 9 1. INTRODUCTION 131.1 The DISPOWER project 14
1.2 Methodology of the work 15
1.3 This report 15
2. DISTRIBUTED GENERATION AND INTERACTION WITH ELECTRICITY
NETWORKS 16
2.1 The changing structure of the power system 16
2.2 Definition of distributed generation 19
2.3 Distributed generation and electricity networks 19
2.3.1 DG network benefits and constraints 20
2.3.2 The role of ICT in network management and market operations 22
2.4 Integration of DG into existing networks 23
2.4.1 Integrating DG in the United Kingdom 23
2.4.2 Integrating DG in Denmark 25 2.5 Future networks 27 2.5.1 Active networks 28 2.5.2 Micro-grids 29 2.6 The values of DG 30 2.7 Conclusion 31
3. TECHNOLOGICAL SOLUTIONS AND PRACTICES 33
3.1 The DISPOWER questionnaire 33
3.2 Part A - Description of technology 33
3.2.1 Name of the solution 33
3.2.2 The status of the technology 34
3.2.3 Type and location of the technology 34
3.2.4 The use of ICT technology 35
3.3 Part B - Benefits and Costs 36
3.3.1 Benefits related to the solution, option or approach 36 3.3.2 Stakeholders benefiting from the solution, option or approach 37
3.3.3 Valuation of benefits 37
3.3.4 Costs related to the solution, option or approach 38
3.3.5 Parties bearing the costs 38
3.3.6 Compensation mechanisms 39
3.3.7 Transfer of benefits and costs among stakeholders 39
3.4 Use of the questionnaire 40
3.4.1 The value of the results 41
3.4.2 Conclusions 41
4. COSTS AND BENEFITS OF DISTRIBUTION NETWORK TECHNOLOGIES 42 4.1 Financial relations in the electricity network 42 4.2 Revenues and expenditures of distribution network actors 45
4.2.1 The DG Operator 45
4.2.2 The Distribution System Operator 47
4.2.3 The energy supplier 48
4.3 Impact of new technologies and approaches 49
4.3.2 Power quality devices 56
4.3.3 Communication devices 58
4.3.4 Storage devices 62
4.4 Allocation of costs and benefits 67
4.5 Conclusion 69
LITERATURE 70
APPENDIX A THE VALUES OF DG 72
A.1 Overview of DG values 72
A.2 The role of connection charges 73
A.3 New approach to connection charging 74
LIST OF TABLES
Table 2.1 Distributed versus large scale generation 19
Table 2.2 Overview of DG values 31
Table 4.1 Financial transactions and information exchange between energy market actors 43 Table 4.2 Financial relations and transactions in balancing and ancillary services market 45 Table 4.3 Changed transactions with WPPT implemented by the energy supplier 52 Table 4.4 Changed transactions with WPPT implemented by the DG operator 54 Table 4.5 Changed transactions with WPPT implemented by the DSO 55 Table 4.6 Changed transactions with GCU implemented by the DSO 57 Table 4.7 Changed transactions with local power management tool implemented by the
energy supplier 61
Table 4.8 Changed transactions with local power management tool implemented by the
DSO 62
Table 4.9 Changed transactions with energy storage implemented by the energy supplier 64 Table 4.10 Changed transactions with energy storage implemented by the DG operator 66 Table 4.11 Changed transactions with energy storage implemented by the DSO 67 Table 4.12 Overview of benefits of technical solutions and practices for distribution
network actors 68
Table A.1 Overview of DG values 72
Table B.1 Planning and design tools 76
Table B.2 Power quality and control devices 77
Table B.3 Communication devices (including ICT applications) 79
LIST OF FIGURES
Figure S.1 Transactions between actors in electricity network system 10 Figure 2.1 Conventional electricity supply system before liberalisation 16 Figure 2.2 Conventional electricity supply systems in a liberalised market 17
Figure 2.3 Electricity supply system with DG/RES 18
Figure 2.4 Production capacity at each voltage level in the Western Part of Denmark 26 Figure 2.5 Network divided into cells acting as independent islands. 28 Figure 4.1 Overview of electricity market transactions and information exchange 43 Figure 4.2 Electricity market transactions in ancillary services and balancing market 44 Figure 4.3 Revenues and expenditures of the DG operator 46 Figure 4.4 Revenues and expenditures of a Distribution System Operator (DSO) 47 Figure 4.5 Revenues and expenditures of an electricity supplier 48 Figure 4.6 Power distributed scheme with DG (wind) operator 51 Figure 4.7 Wind power prediction tool implemented by the energy supplier 52 Figure 4.8 Wind power prediction tool implemented by the DG operator 53 Figure 4.9 Wind power prediction tool implemented by the DSO 54
Figure 4.10 Grid control unit operated by the DSO 57
Figure 4.11 Basic power distribution scheme 59
Figure 4.12 Local power management tool used by the energy supplier 60 Figure 4.13 Local power management tool used by the DSO 61 Figure 4.14 The location of a storage device in a distribution power scheme 63 Figure 4.15 Energy storage device implemented by the energy supplier 64 Figure 4.16 Power storage device implemented by the DG operator 65 Figure 4.17 Power storage device implemented by the DSO 66
ABBREVIATIONS
AC/DC Alternating current/direct current
CAPEX Capital Expenditures
CHP Combined Heat and Power production DEMS Decentralised Energy Management System
DG Distributed Generation
DISPOWER Distributed Power (5th Framework Research Project) DSO Distribution System Operator
GCU Grid Control Unit
ICT Information and Communication Technology
IPP Independent Power Producer
kV kilovolts
LV Low Voltage
MV Medium Voltage
MW Megawatt
NETA New Electricity Trading Arrangements OFGEM UK Office of Gas and Electricity Markets
OPEX Operational Expenditures
PANDA Plan And Data Acquisition System
PoMS Power operation and power quality Management System R&D Research and Development
RES Renewable Energy Sources
SCADA Supervisory Control And Data Acquisition System
SUSTELNET Sustainable electricity networks (5th Framework Research Project) TSO Transmission System Operator
UoS Use of System
VA Volt Ampere
VAr Volt Ampere reactive
EXECUTIVE SUMMARY
Distributed generation (DG), connected to the distribution network or at the customer side of the meter is gradually changing the electricity supply system in Europe. The share of DG is increas-ing due to a number of powerful drivers: technical developments in the field of generation tech-nology, enhanced policies for climate change and sustainability, security of energy supply and the liberalisation of electricity markets.
DG influences the arrangement of the power system as it interacts in a different way with the network system than centralised generation. DG can be located at weak low voltage grids, can be of an intermittent nature and may require additional reserve capacity. Apart from these con-straints, DG can present several advantages to the network. DG may be able, when located close to loads, to reduce losses in transmission and distribution networks, postpone necessary network investments and provide local ancillary services.
So far DG has been considered to be a passive appendage of the distribution network, not inter-acting with the network. For the future, this approach presents major challenges to the develop-ment of DG. It limits the further growth of DG as the network reaches its physical barriers or costly network upgrades will become necessary. An alternative is to look for more cost-effective network management and to view the distribution network and DG as an integrated structure, interacting and affecting each other.
Examples from Denmark, the country currently with the highest share of decentralised electric-ity production, show that substantial DG production can influence the whole network. For the UK, where the share of DG so far is relatively low, studies examining the impact of the UK’s ambitious targets show that the additional costs for reserve and balancing may be substantial. To cope with these problems, several alternative concepts have been considered, such as the ac-tive networks and Micro-grids concept. Although having slightly different features, both con-cepts see an important role for network control on medium and lower voltage levels.
As such concepts require special technical approaches, in this research the socio-economic im-pact of the application of these technical approaches in current liberalised electricity markets was studied. First an inventory was made of technical options and approaches to improve the integration of DG into distribution networks. To identify such specific technical solutions, op-tions and approaches to improve the integration of distributed generation technologies a ques-tionnaire has been developed and distributed among DG (technical) experts. The quesques-tionnaire was not meant to give an exhaustive overview, but to gain insight in the possible technical solu-tions, options and approaches and the economic interactions with different actors in the electric-ity market.
The questionnaire presented a number of options, varying from software tools (communication, planning supply and demand) to devices such as energy storage. The response of the question-naire showed that excellent technical solutions are present at different levels of development that may smoothen the integration and interaction of DG with the network. When implementing these technologies in actual network management, however, one key issue remains: which party will invest in such a technology, especially when part of the benefits will accrue to another party?
To assess the impact of the investment in the proposed technologies on all actors involved (and different actors investing), an assessment tool has been developed to qualitatively identify im-pacts of a number of these options. This assessment tool takes into account the financial
transtions between the parties on the distribution network according to Figure S.1. This research ac-tivity in the DISPOWER project merely provides an analytic tool how to identify the costs and benefits of a number of proposed technologies and how to allocate them between actors in the electricity market.
DG operator
DG operator Energy
supplier Energy
supplier ConsumerConsumer
DSO DSO TSO TSO Commodity Physical Large power producer Large power producer Ancillary services market Ancillary services market Balancing market Balancing market storage DG operator DG operator Energy supplier Energy
supplier ConsumerConsumer
DSO DSO TSO TSO Commodity Physical Large power producer Large power producer Ancillary services market Ancillary services market Balancing market Balancing market storage
Figure S.1 Transactions between actors in electricity network system
The different technical options and solutions have been divided into four main categories. Four technologies, one of each category, have been studied in more detail to analyse their impact on the financial relationships between the actors in the distribution network. The four technologies are:
• wind power prediction tool (planning tool), • grid control unit (power quality device),
• power operation and power quality management system (ICT device), • power storage device.
Based on this analysis a number of conclusions can be drawn:
• Investments in the technical options have the potential to improve the integration of DG in several ways, for example:
- increased or optimised power production (DG operator),
- access to markets for balancing and ancillary services (DG operator), - reduced balancing costs (energy supplier),
- ability to construct a more exact E-program, and better comply with the E-program (en-ergy supplier),
- improved power quality (distribution system operator),
- reduced operational and capital expenditures (distribution system operator).
• Each of the three parties investigated, the energy supplier, the DG operator and the distribu-tion system operator (DSO) have their own reason for investing in a specific technical op-tion.
• All solutions have, next to a number of direct impacts for the actor investing, a number of indirect impacts to the other actors on the distribution network.
• For all parties to benefit optimally from the technical solution, an economic efficient alloca-tion of costs and benefits will be needed, which should be carried out according to the fol-lowing line:
- the party investing receives the economic value of the benefits directly,
- allocation of the economic value of benefits experienced by other parties through con-tractual arrangements (e.g. changes of concon-tractual prices) or network regulation (e.g. changes of network charges).
• The DSO often plays a central role in many of the technical options and solutions, even if other parties do the investment. However, the DSOs cannot change the system of network charges themselves and are therefore restricted in the transfer of benefits and costs. It is important that this is recognised by policymakers and regulators.
• The allocation between energy suppliers and DSOs might be difficult because of absence of financial relationships. The regulatory framework should allow DSOs to enter contracts with energy suppliers, in particular because this will contribute to the transparency of the unbundling of utilities.
• The allocation of indirect benefits proves to be difficult because of the missing financial relationship with the party investing. Only via economic regulation the economic value of these indirect benefits (or costs) can be transferred via TSO and DSOs through network or system charges.
The analyses performed with the tool, developed in this research activity, showed a number of benefits and costs that can be taken into account when parties involved in the electricity supply invest in new technical solutions and options to integrate distributed generation. Follow-up re-search activities will have to quantify these benefits and costs identified and, of equal impor-tance, the regulatory constraints that limit a ‘flexible’ allocation of costs and benefits between distribution network actors.
1. INTRODUCTION
Electricity supply systems were originally developed in the form of local generation facilities supplying local demands, being built and operated by independent companies. During the early years of development, this proved to be quite sufficient. Around the 1950s it was recognised, however, that an integrated system was needed that was both reasonably secure and economic. For this reason, the electricity supply system in Europe has been developed during the past 50 years into such a pre-dominantly centralised system with a limited number of large power pro-ducers. Electricity is nowadays mainly produced in large power stations and transported over a transmission network, sometimes over considerable distances, and passed down through a dis-tribution network for delivery to the customers. However, recently there has been a revival of interest in connecting small-scale power generation plants, mainly small-scale renewable energy sources (RES) and combined heat and power (CHP) plants, to the distribution network or at the customer side of the network. This type of generation is also known as distributed or embedded generation1.
The growing interest in distributed generation (DG) has been triggered by four major develop-ments influencing the energy sector (ten Donkelaar, 2004):
• Technological developments in the field of generation and distribution technology.
• Liberalisation of the electricity markets, leading to stronger market competition and unbun-dling of generation and network facilities.
• The increasing importance of security of energy supply and the need for diversification of energy sources.
• The adoption of international environmental and sustainability targets (such as the Kyoto Protocol and the Renewable Electricity Directive) strongly influencing fuel choices for power generation.
Altogether these developments create opportunities for a gradual increase of the contribution of DG technologies that are better equipped than centralised power sources to meet the require-ments of future electricity systems. DG facilities are normally located close to the site of the end-user, thereby reducing the need for transmission and distribution investment, while contrib-uting to resolving many system constraints and reducing line losses.
Although many benefits of DG have been identified, there are a number of constraints that have to be overcome. First of all, there is a number of technical barriers on the network that can pre-vent a rapid increase of DG. An increasing share of distributed generation influences the ar-rangement of the power system. This is especially the case for renewable energy sources that have a much lower energy density than fossil fuels and so generation plants are smaller and geographically wider spread. In countries where the share of DG has been rapidly growing, the electricity networks are facing new challenges in terms of network stability and power quality, complicating the tasks of network operators. New technologies have to be developed to keep the electricity network running in an equally reliable way. The second barrier is of a more regula-tory nature. The existing network regularegula-tory framework, including grid connection, access to wholesale markets, balancing arrangements, etc. are usually biased in favour of centralised gen-eration. Closely related to these issues are the economic barriers. DG incurs certain costs, but also certain benefits to the electricity network and society as a whole. Existing regulation, how-ever, does not enable a proper allocation of these costs and benefits and therefore hinders a more (economically and technically) optimised integration of DG.
1
Directive 2003/54/EC concerning common rules for the internal market in electricity defines distributed generation as “generation plants connected to the distribution system”.
1.1 The
DISPOWER
project
The cluster of DG research projects within the Fifth Framework Research Programme aims to tackle all technical, socio-economic and institutional barriers DG is facing in the current situa-tion2. One of these projects is the DISPOWER project that, undertaken by 37 different research partners from 11 European Member States, intends to support the transition of nowadays elec-tricity supply towards a more decentralised and market oriented supply structure with new con-cepts, strategies and tools. For maintaining a reliable and cost effective electricity supply, new efforts have to be undertaken for the management of electricity networks and the integration of RES and other decentralised units in the distribution networks.
Socio-economic research on technological solutions and options
The integration of DG into current electricity supply networks includes many socio-economical and institutional issues that can pose a barrier to this integration and to the further growth of DG potential. These issues are studied in Work Package 3 of the project. This Work Package in-volves four tasks (activities) aiming at the following issues:
3.1 Inventory of technical solutions and practices - Demand side.
3.2 Inventory of technical solutions and practices - Supply side - This report. 3.3 Analysis of consumer responses to new communication technologies.
3.4 Competition strength of DG and RES in a liberalised market and the roles of ICT and inno-vative distribution networks.
Task 3.2, included in this report, aims at analysing the technological solutions and practices that improve the overall integration of DG and RES into the existing distribution network. Such technical solutions include for example the dispatch of DG and RES, improving the system bal-ancing and power quality, optimising use of generation and network capacity and improving an-cillary services. The aim of this part of the study is to get some understanding of the costs and benefits of the technological solutions and options and the possible transfer of these costs and benefits between different actors in the electricity supply system.
For example a distributed generator might be dispatched automatically on basis of real time electricity market prices. Obviously, the operator of this distributed generator benefits from the automatic system, but so does the electricity supplier/trader that purchases the electricity. A third party, the network operator, may bear the costs of this automatic system, but may also benefit from this dispatch because DG reduces the network losses or can avoid network rein-forcements. The proper transfer of costs and benefits in cases like this between different parties and functions in the electricity supply system (generation, trade, transmission/distribution, con-sumption) is vital for the implementation of DG. It may be difficult, however, to realise such transfers in liberalised energy markets where these separate functions are undertaken by sepa-rate parties.
This task makes an inventory of technical solutions and practices studied within the DIS-POWER project and other DG projects that may facilitate the penetration of RES and DG. A distinction is made between ICT technologies (to improve communication and transfer of in-formation on loads, prices, dispatch, etc.) and other innovations in distribution networks (stor-age, network configuration, etc.). In Task 3.4 the impact of the market structure and regulation on the use of these technical solutions and practices is analysed. The results of this analysis are published in a separate report.
2
1.2
Methodology of the work
An inventory has been made of technological solutions and practices that improve implementa-tion of distributed generaimplementa-tion and renewable energy sources. For the purpose of this inventory a questionnaire has been developed and further improved after a test among a small number of experts. The questionnaire aims at obtaining information from technical DG experts on benefits and costs of new technological solutions and approaches and the probable/estimated transfer of these benefits and costs between different actors in the electricity supply system. The question-naire has been sent to participants in the DISPOWER project as well as in some other DG pro-jects in the 5th Framework Programme (all part of the DG cluster). For this activity, a distribu-tion list has been drawn up of approximately 140 experts, who received the quesdistribu-tionnaire in the beginning of 2003. The respondents have been asked to present a certain technology and to de-termine its benefits and costs for the power distribution system. In case that not all benefits of the technology accrue to the party that is investing in the technology, the respondents were asked how the transfer of benefits (and costs) could take place. Results from the questionnaire have been integrated in further analysis of cost/benefit allocation of distribution network tech-nologies.
1.3 This
report
This report will start with a general overview of distributed generation and its interactions with the electricity network (Chapter 2) based on literature and information from other Fifth Frame-work DG Research. This interaction will be illustrated on the basis of concrete examples from European Countries. This chapter will shortly analyse new approaches in network management that are currently being developed. It includes a description of the electricity markets and the changing relations due to development and integration of distributed generation. Chapter 3 pre-sents the results of the DISPOWER questionnaire and inquires socio-economic aspects of tech-nical solutions. In Chapter 4, some of the cases from the questionnaire will be analysed into de-tail according to financial transaction schemes developed in this chapter. Results from this chap-ter will show how technical options, solutions and approaches impact on the revenues and ex-penditures of different parties in the electricity supply system. These schemes will be used later on in a follow-up report in the framework of Work Package 3.4 to make a detailed analysis of several promising options for the integration of DG into distribution networks.
2. DISTRIBUTED
GENERATION
AND
INTERACTION
WITH
ELECTRICITY NETWORKS
The electricity supply system is experiencing two major developments, one is the opening up of the electricity market to new players and the unbundling of integrated energy companies, the second is the growing integration of distributed generation technologies in the electricity mar-ket. This chapter will describe some of the main features of distributed generation technologies and its interactions with the electricity network, both from a technical as an economical view-point. The interactions will be illustrated based on some country examples, such as Denmark and the United Kingdom. An increasing level of distributed generation may require technologi-cal adaptations to the network, but this increase can also be an incentive towards completely new ways of network development to facilitate a larger share of DG than would be possible within the current network infrastructure. Several new approaches for the development of the electricity network infrastructure will be investigated.
2.1
The changing structure of the power system
Modern electrical power systems have been developed over the last 50 years according to the following arrangement. Large central generators feed electric power up through generator trans-formers to a high voltage interconnected transmission network. The transmission system is used to transport the power, sometimes over considerable distances, which is then extracted from the transmission network and passed down through the distribution network for delivery to the cus-tomers. The conventional arrangement of a modern large power system offers a number of ad-vantages. Large generating units can be made efficient and operated with only a relatively small number of personnel. The interconnected high voltage transmission network allows generator reserve requirements to be minimised and the most efficient generating plant to be dispatched at any time, and bulk power (e.g. from hydropower plants or coal power plants sites near coal mines) can be transported over large distances with limited electrical losses. The distribution networks can be designed for unidirectional flows of power and sized to accommodate customer loads only.
The conventional electricity supply system before electricity market liberalisation was relatively straightforward as it included one way transport of electricity from the producer through the transmission and distribution network to the consumers. This is shown in Figure 2.1.
Large consumers Large consumers Primary energy source Primary energy source Small consumers Small consumers Large electricity generation Large electricity generation Transmission network Transmission
network Distributionnetwork Distribution network Large consumers Large consumers Primary energy source Primary energy source Small consumers Small consumers Large electricity generation Large electricity generation Transmission network Transmission
network Distributionnetwork Distribution network Primary energy source Primary energy source Small consumers Small consumers Large electricity generation Large electricity generation Transmission network Transmission
network Distributionnetwork Distribution
network Figure 2.1 Conventional electricity supply system before liberalisation
When the electricity market was liberalised in most European countries during the late nineties, some of the activities of the previously integrated companies (responsible for production,
trans-port and supply to the customer) were unbundled according to the requirements stated in the EU directives3. This situation is shown in Figure 2.2.
Primary energy source Primary energy source Small consumers Small consumers physical commodity unbundling Large electricity generation Large electricity generation Transmission network Transmission network Wholesale market Wholesale
market marketRetail Retail market Distribution network Distribution network Large consumers Large consumers Balancing market Balancing market Ancillary service market Ancillary service market Primary energy source Primary energy source Small consumers Small consumers physical commodity unbundling Large electricity generation Large electricity generation Transmission network Transmission network Wholesale market Wholesale
market marketRetail Retail market Distribution network Distribution network Large consumers Large consumersconsumersLarge
Large consumers Balancing market Balancing market Ancillary service market Ancillary service market Balancing market Balancing market Ancillary service market Ancillary service market Balancing market Balancing market Ancillary service market Ancillary service market
Figure 2.2 Conventional electricity supply systems in a liberalised market
The major difference with the previous system is that the physical transport of electricity through transmission and distribution networks is separated from the supply of the commodity to consumers through wholesale and retail markets. In some markets liberalisation also leads to the establishment of two other markets, the balancing and the ancillary services market. On the balancing market a power producer offers surplus power or the option of regulating the power generation output. The TSO, whose task it is to ensure system balance, purchases this surplus power or regulation option in order to correct unbalance between supply and demand. On the ancillary services market, other services related to reactive power, voltage control, etc. are being offered. As transport and distribution of electricity remain monopoly activities for the incum-bent energy companies, new companies may enter the markets for generation, trade and retail. However, the operation of transmission and distribution networks should be unbundled4 from the other activities to avoid abuse of the monopoly.
These figures only consider the (conventional) centralised electricity supply system. Since the 1980s, however, there has been a considerable increase in interest in distributed generation. In most countries, DG facilities were already present before the liberalisation and were operated by the incumbent, large power producers or by consumers. Environmental policy, also addressing climate change and support of renewable energy sources, led to an increased interest in invest-ing in (mostly small-scale) renewable energy and combined heat and power units. In terms of the scheme in Figure 2.1 the only difference between these distributed energy sources and cen-tralised electricity sources is the location of the connection to the electricity grid, the distribu-tion network instead of the transmission network.
The liberalisation of the electricity market also changed the position of the small generating units, presenting new opportunities for participation on different markets. Their current position in the electricity supply system can be illustrated according to Figure 2.3.
3
Directive 2003/54/EC of 26 June 2003 concerning common rules for the internal market in electricity and its prede-cessor Directive 96/92/EC.
4
Directive 2003/54/EC requires legal unbundling. In some countries, more strict unbundling by ownership is re-quired.
Primary energy source Primary energy source Small consumers Small consumers physical commodity unbundling Large electricity generation Large electricity generation Transmission network Transmission network Wholesale market Wholesale
market marketRetail Retail market Distribution network Large consumers Large consumers Primary energy source Primary energy source Distributed generation Distributed generation Balancing market Balancing market Ancillary service market Ancillary service market Primary energy source Primary energy source Small consumers Small consumers physical commodity unbundling Large electricity generation Large electricity generation Transmission network Transmission network Wholesale market Wholesale
market marketRetail Retail market Distribution network Large consumers Large consumers Primary energy source Primary energy source Distributed generation Distributed generation Balancing market Balancing market Ancillary service market Ancillary service market
Figure 2.3 Electricity supply system with DG/RES
Distributed generators deliver electricity directly to (large/small) consumers or via the electric-ity (mainly retail) market to these consumers. In more developed electricelectric-ity markets were DG has gained a more equal position, DG operators may also gain access to the balancing and ancil-lary services market. This is not yet the case in many countries, however.
The function of the distribution network will change, because the flows through the network may reverse. The networks no longer only distribute electricity but provide connectivity be-tween the actors connected to the electricity system (see the two-way arrows in Figure 2.3). The full access of DG to electricity markets, including markets for balancing and ancillary services, may help in creating an equal position for DG compared to centralised generation, in other words, creating a level playing field. The SUSTELNET project (5th Framework Project) con-cludes that to create a level playing field and hence a possible change towards a more decentral-ised electrical system, has to be valued in economic terms in order to consider the benefits and costs of DG in the regulatory framework5. This is not a simple task, especially because there are short-term and long-term effects to the system. E.g. the introduction of DG will positively or negatively influence grid losses in the short-term, but will also in the long-term influence future grid extensions.
There is general agreement that a level playing field entails markets and regulation that provide neutral incentives to centralised versus distributed generation. This requires that all the values of DG are recognised, and that appropriate mechanisms are set up to put a monetary value to these values. Furthermore, incentives should be provided to network operators and generators to ex-ploit these values in the best possible way. Access to all electricity markets - including whole-sale, retail, balancing and ancillary service markets - are essential elements in reaching this level playing field.
5
2.2
Definition of distributed generation
Although distributed generation has gained major importance, no general definition of what DG is has been agreed upon. There are, however, some commonly agreed features that characterise these sources (Jenkins, et al, 2000):
• DG is not centrally planned and is usually operated by Independent Power Producers (IPPs) or consumers.
• DG is not centrally dispatched. • DG is normally smaller than 50 MW.
• DG is usually connected to the distribution network.
• The distribution system is taken to be those networks to which customers are connected di-rectly and which are typically of voltages from 230/400 V up to 110 kV.
It appears difficult to pin down DG on specific numbers because this is country specific and re-lates to characteristics of the national (centralised) power system. Cogeneration (or Combined Heat and Power production - CHP) and renewable energy sources (RES) are often considered as DG. However, only a part of CHP and RES can be considered as DG. Within the SUSTELNET project an attempt has been made to divide categories of RES and CHP in large scale and dis-tributed generation, as can been seen from Table 2.1. For example, renewable energy sources such as large hydropower plants and offshore wind parks with capacities of 100 MW and more that feed in electricity to the transmission grid cannot be considered as distributed generation. Table 2.1 Distributed versus large scale generation
Combined Heat and Power (CHP) Renewable Energy Sources (RES) Large-scale generation. • Large district heating*
• Large industrial CHP*
• Large hydro** • Off-shore wind
• Co-firing biomass in coal power plants
• Geothermal energy Distributed Generation
(DG)
• Medium district heating • Medium industrial CHP • Commercial CHP • Micro CHP
• Medium and small hydro • Onshore wind
• Tidal energy • Biomass and waste
incineration/gasification • Solar energy (PV) * typically > 50 MWe. ** typically > 10 MWe.
2.3 Distributed
generation
and electricity networks
An increasing share of distributed generation influences the arrangement of the power system. One of the major reasons is that some types of DG, such as renewable energy sources, have a much lower energy density than fossil fuels and so the generation plants are smaller and geo-graphically wider spread. For example wind farms must be located in windy areas, while bio-mass plants are usually of modest capacity due to the cost of transporting fuel with relatively low energy density. These small plants, typically of less than 50 MW in capacity, are then con-nected to the distribution system. In some countries, the majority of the new renewable genera-tion plants are not planned by the incumbent utility but developed by independent power pro-ducers and are therefore not centrally dispatched. The intermittent nature of sources like wind energy cause that these sources only generate whenever the energy source is available, requiring the availability of reserve capacity. Combined Heat and Power (CHP) schemes make use of the waste heat of thermal generating plants for either industrial processes or space heating and are a
well established way of increasing overall energy efficiency. Transporting the low temperature waste heat from thermal generation plants over long distances is often not economical and so it is necessary to locate the CHP plant close to the heat load. This again leads to relatively small generation units, geographically distributed and with their electrical connection at the distribu-tion network. Although CHP units can, in principle, be centrally dispatched, they tend to be op-erated in response to the requirements of the heat load or the electrical load of the host installa-tion rather than the needs of the public electricity demand. As CHP units are operated close to a residential or industrial heat load, this means that electricity loads are often located nearby and the power infrastructure is relatively strong. This is not always the case for other DG sources as wind, biomass and small hydro, often located in areas with weak lines.
2.3.1 DG network benefits and constraints
Distributed Generation facilities are nowadays connected to the distribution network at low voltage levels, at sites that were originally not meant to connect power generation facilities. Es-pecially when large amounts of DG are connected at locations with little local load, this will in-crease the burden on the distribution lines. This new situation can create several problems for the distribution networks in terms of stability and power quality.
Due to the aforementioned issues, distributed generation is at present almost exclusively seen as a negative load and making no contribution to other functions of the power system (e.g. voltage control, network reliability, reserve capacity, etc.). But given the increased use of technologies such as fuel cells, micro-CHP, wind turbines and PV cells, ways to effectively integrating them into the electricity networks have to be found, preventing considerable impacts and costs of (distribution) network upgrades.
Apart from a number of constraints, distributed generation also presents several advantages to the electricity network6. DG can reduce transmission and distribution losses by reducing the cur-rent flow from the transmission system through the transformers and conductors on the distribu-tion system. This largely depends, however, on the locadistribu-tion of a specific DG facility. If a small distributed generator is located close to a large load then the network losses will be reduced as both real and reactive power can be supplied to the load from the adjacent generator. Con-versely, if a large distributed generator is located far away from network loads then it is likely to increase losses on the distribution system. A further complication arises due to differing values of electrical energy as the network load increases. In general there is a correlation between high load on the distribution network and the use of expensive (peak) generation plant. Thus, any dis-tributed generation plant that can operate in this period and reduce distribution network losses will make a significant impact on the costs of operating the network. However, if the DG supply exceeds the local electricity demand7, network capacities have to be increased, in order to trans-port the electricity to other demand areas via the transmission grid, thereby increasing line losses.
Another specific network benefit is possible distribution capacity cost deferral. The develop-ment of small-scale DG facilities near a load can postpone necessary investdevelop-ments in additional distribution and transmission capacity. Network operators can benefit from these new DG facili-ties as they can reduce their investment costs in upgrading or extending the distribution net-work. Certain types of DG also have the ability to offer certain network ancillary services to the network operator, such as reactive power support and voltage control, improving power quality.
6
An extensive overview of DG costs and benefits is presented in Appendix A.
7
However, with these benefits come many operational, technical and commercial challenges for the Transmission System Operator (TSO) and especially for the Distribution System Operator (DSO)8.
The majority of new and renewable energy plants being connected to the distribution network in most European countries at present is powered by wind or in the form of CHP and is generally connected at the 11-66 kV levels. This forces the DSO’s to reconsider their approach to network design and management. If the future electricity system is to accommodate the expected growth in DG at lower voltages it will need to change from a design standpoint as well as from a man-agement and commercial perspective.
The emergence of micro power units or small-scale DG9, which may be located in the domestic home or small business, and connected to the distribution network via the metering system, could take the trend for lower voltage connection a step further. These units are often connected to the very low voltage level (< 1 kV) and often are single phase, which presents new challenges for the DSO. With the introduction of domestic CHP and small scale DG in general, the DSO faces potential technical challenges, which may require engineering and design changes to the system, and a more holistic approach to system management10. The present and future increase in DG facilities being connected to the distribution network at all levels means that the network characteristics such as bi-directional power flow, central dispatch of DG, provision of ancillary services by DG operators and islanding may become commonplace. Connection of generators will also have to become far simpler and more transparent at all voltage levels, particularly at the lowest voltage levels where the generating plant connections could be smaller and more nu-merous. In the case of small scale DG, the DSO may not even know of the connection until after it has taken place, which could have safety implications.
In countries with a large share of DG connected to the distribution network, such as Denmark and the Netherlands, it is already recognised that distribution networks can no longer be consid-ered as passive appendages to the transmission network, but that the whole network must be op-erated as a closely integrated unit. For this purpose a number of technical improvements have to be developed and implemented. Conditions for central and local electricity production must be equalised bringing all power plants to contribute to system stability and flexibility.
Several technical experts have addressed the issue of growing DG levels in existing distribution networks (Nielsen, 2002a; Strbac & Jenkins, 2001). They argue that if the penetration level of distributed generation continues to grow while the distribution grid remains unchanged, a chain of technical conflicts may develop, unless such issues as operation, control, and stability of dis-tribution networks with DG installations are properly addressed. There are several aspects that need to be fully understood in order to obtain maximum benefits from both DG and the power grid, mainly:
• The distribution network and DG are interacting and actively affecting each other.
• No generic conclusion can be made regarding the influence of DG on the grid, as various power sources have quite different characteristics. Instead, individual cases have to be treated separately.
• Both DG and the grid should be studied as one integrated, flexible, dynamic and complex structure, for to a great extend, they do have a major impact on operation, control and stabil-ity of each other.
8
For the operator of the distribution network (150 kV and lower) both the terms Distribution Network Operator (DNO) and Distribution System Operator (DSO) are used. Directive 2003/54/EC concerning common rules for the internal market in electricity defines the DSO as operator of the distribution network. The term DSO will also be used in this report.
9
The most common categories of small-scale DG are domestic CHP, photovoltaic, micro-wind, micro-hydro and fuel cells. In the case of the UK see Forrest & Wallace (2003), Domestic CHP is the most feasible option.
10
The network constraints of DG can be solved to a certain extend when the capacity of the (dis-tribution) network is reinforced. From an economic point of view, this is not very attractive as it concerns long-term investments. Other, more cost-effective ways of network management will have to be considered.
2.3.2 The role of ICT in network management and market operations
The random nature of loads in an electrical network and the limited capacity to store electrical energy in significant quantities, exemplifies some of the challenges involved in managing elec-trical networks. This in addition to the fact that, elecelec-trical networks are never in a steady state condition, but rather in a perpetual dynamic state. When large amounts of distributed generation are included in the electricity network, the need for information exchange and operational con-trol will grow. In the classical electricity network, with its predominantly top-down structure, little operational co-ordination was required between the transmission and distribution net-works, both under normal conditions and in emergency situations.
In today's electricity networks, communication is, and will be in an even greater extent, a neces-sary tool for the operation of the electrical networks, both for technical as well as for adminis-trative purposes. In the (even recent) past communication remained a limiting factor. Due to the rapid developments in ICT technology, the increasing communication capacity now provides possibilities for operating the electrical network in a different and, quite often, more efficient way. Increasing the communication capacity is not only required because of the integration of large amounts of DG on the distribution network, but also due to the establishment of electricity markets.
The establishment of electricity markets (e.g. markets for wholesale, balancing) has major im-plications for network management as it increased the need for exchanging information between the network operators, the power exchange and the market players. The transmission system op-erators, for example, must treat all players neutrally and in a non-discriminatory way, meaning that all the information given to one player must also be given to another player. The largest challenge for the TSO to manage this system is to co-ordinate all the decisions and actions of producers (how much electricity is produced with what power plant). This requires an enormous amount of data exchange and IC technology has been a necessary tool to support the operation of the electricity market.
The classical ways of communication through narrow-band solutions (range of 100 bit/s) have in many cases, at the introduction of fibre optics solutions, been replaced by broadband commu-nication highways (range of 100 Mbit/s). It is only with the development of modern communi-cation methods that systems like SCADA and PANDA have become feasible:
• SCADA - The Supervisory Control and Data Acquisition System is concerned with provid-ing the system operator with remote information and the control of remote facilities in order to operate in the most reliable, efficient and economical manner. The advantage of this scheme is that the operator is acting upon data, which represent the actual operation condi-tion throughout the whole system at any given instant. There is a good possibility to develop a web-based SCADA system.
• PANDA - The Plan And Data Acquisition System is concerned with providing the market operator with schedules, measurements and the ability to make settlements.
Due to the introduction of electricity markets, two parallel systems have evolved. The control and the market system could be integrated into one overall TCP/IP network and at the same time make the communication system an integrated part of the electrical network (Nielsen, 2002b).
2.4
Integration of DG into existing networks
The issue of increasing levels of DG on the lower and medium voltage level is now discussed and investigated in many European countries, such as Denmark, Germany, the Netherlands and the United Kingdom. This section will give an illustration of the situation in two countries: • The United Kingdom, having ambitious RES targets but experiences difficulties to combine
electricity market liberalisation with an increased use of CHP and RES.
• Denmark, introducing massive support for wind energy and CHP but lagging behind in network regulation.
2.4.1 Integrating DG in the United Kingdom
Several years ago, the United Kingdom adopted an active strategy regarding measures to pre-vent climate change. This climate change policy includes also ambitious targets for renewable energy, the aim being to generate 20% of electricity from renewable energy sources by 2020 (compared to 3% in the year 2000). A large part of this share will be in the form of distributed generation.
The United Kingdom is facing two main barriers in reaching these ambitious targets:
• The existing UK network regulation does not favour the full integration of RES and CHP into the distribution network.
• Technical barriers of integrating DG when operating the network in the traditional way. The primary source of income for DG is sale of energy. How much energy DG can sell in the UK and the risks associated with this activity are largely dependent upon the electricity market structure and the regulatory environment in place. For example the New Electricity Trading Ar-rangements (NETA) implemented in the UK in 2001 introduced a number of risks for distrib-uted generation.
The key element of NETA that introduces significant risks for distributed generation is the pe-nal dual cash out prices of the balancing mechanism. If a generator delivers less energy than it has contracted for in a settlement period then it must pay the system buy price (SBP) for the shortfall. This is the weighted average of offers accepted in the period. If it over generates in a period then it receives the, normally lower, system sell price (SSP) for the excess. This is the weighted average of bids accepted in the period. The mechanism was designed to encourage market participants to contract in the markets and power exchanges at gate closure. In the first few months of NETA, SBP was extremely volatile and so the earnings risk if a generator failed to deliver its contract position was high. NETA awards predictable plants, as the contract posi-tion for the generator must be submitted at gate closure, which is currently 1 hour ahead of the delivery period. A large part of DG in the UK consists of Combined Cycle Gas Turbines (CCGT) that have a relatively predictable output. It might therefore be expected that the earn-ings risk for these generators due to imbalance will be low. This depends, however on the type of generator (intermittent or non-intermittent) and the level of the SBP. The volatility of the SBP may be such that a forced outage occurring during a price spike could have serious effects on the earnings of an independent generator.
Anticipating on the increase of the share of DG in the electricity supply system Strbac & Jen-kins (2001) have analysed the security of the UK electricity supply system in the context of a growing penetration of distributed generation technologies. Under the present conditions the owners and operators of the distribution networks, the DSOs, anticipate that they can integrate only a very limited amount of generation capacity without major reinforcement. The potential bottleneck for RES and DG targets for 2010 and beyond in the UK (and perhaps in more Euro-pean countries) is the distribution system, and it may be necessary to change the operational
practices of distribution networks in order to accommodate the expected increase in renewable and CHP generation.
Another study (ILEX Consulting & Strbac, 2002) shows that increasing the share of DG from 10 to 20/30% may substantially increase the costs for network reinforcements. Depending on the location of the DG plants and the share of intermittent sources (e.g. wind) the reinforcement costs may increase with 150 up to 900 million GBP per annum11. This reinforcement mainly in-cludes costs for balancing and reserve capacity, when introducing large amounts of (intermit-tent) power sources such as wind turbines to the power system. The costs for the distribution system vary between 6 - 55 million GBP per annum. The costs for the transmission networks will be mainly influenced by the location of new renewable generation plants. In the UK, sig-nificant wind resources can be found in Scotland and the North of England, far away from the major loads in the south of England. A significant growth of wind power in the North will in-crease the requirement of transmission reinforcements and the level of transmission losses. Alternatively, if the additional renewables were more evenly developed across Great Britain, transmission reinforcement costs could be negligible and transmission losses might be reduced. When integrating large amounts of DG into the distribution network, the role of the Distribution System Operator (DSO) is viewed to be crucial. So far the major, and sometimes only responsi-bilities of DSOs are:
• to maintain voltage fluctuations on the system within limits (specified by standards), and • to ensure that the quality of power delivery is adequate.
This ‘passive’ approach to network operation considerably limits the amount of DG that can be connected and DG is effectively excluded from the opportunity to support the DSOs in carrying out the main duties.
Regulatory incentives need to be designed to encourage DSOs to consider assets and services of all network users (such as DG) for the provision of voltage control and service quality. This would lead to unbundling of distribution network services and the development of commercial arrangements within which the DSOs would carry out their responsibilities efficiently and at least cost, considering the assets and services offered by all participants.
In order to increase the ability of the existing distribution network to absorb large amounts of distributed generation (without considerable reinforcement of the power grid), active manage-ment of distribution networks12 may be the most economic solution. Such an active approach requires the involvement (dispatch) of DG installations in tackling network problems such as voltage control in rural areas. It is well known that in rural networks the voltage rise effect is the main limiting factor for connecting DG. The voltage profile in distribution networks with DG can be controlled effectively within an active network approach. Preliminary investigations show that the amount of DG that can be connected to an existing system can be increased with a factor of 3-5 by the use of these approaches.
Maintaining the current level of system security with a generation mix containing significant renewable generation will become more difficult. However, it is believed that all the issues can be addressed by technically feasible engineering approaches within reasonable economic con-straints.
• Up to 2010 the main priority will be to integrate the operation of DG and distribution net-works and no significant issues related to system security are likely to emerge.
• In the medium-to-long term, with a considerably larger contribution of DG, maintenance of system security will require integration of this generation in the operation and development
11
1 GBP = 1.47 Euro (March 2004 exchange rate)
12
of the entire power system. Balancing demand and generation will be a matter of primary importance and a considerably increased generation margin will be required to deal with intermittency of the new renewable generation. The new generation (together with storage and Demand Side Management) would have to assume responsibility for security through flexible operation. Incentives for maintaining generation capacity and flexibility need to be developed.
The concept of Power Zones
Ofgem, the UK Office of Gas and Electricity Markets, has recently introduced the concept of power zones in one of its discussion papers (Ofgem, 2003). Ofgem is of the opinion that the network developments necessary to accommodate the growing capacity of DG are most likely to be achieved efficiently if innovative solutions and technologies are employed.
Most of the DG capacity connected in the UK in the past 10 years has been connected on a ‘fit and forget’ basis. In other words, the DG plant is connected in such a way that no active control is required by the DSO. This approach is feasible when the penetration of DG is low, but new technical and commercial strategies are required when the number and capacity of DG plants is increasing. This will ensure that network connection, reinforcement and operating costs are maintained at efficient levels. Ofgem believes that DG connection costs are likely to rise if the fit and forget approach continues and in certain circumstances connection may not be possible unless new technologies and solutions are developed, proven and adopted.
There are, however, a number of risks associated with the application of the new technologies, options and approaches by the DSO. This mainly includes certain business risks, as the men-tioned approaches do not belong to the day-to-day business of DSOs.
The ‘Registered Power Zones’ proposal is intended to offer DSOs a sufficient incentive to en-courage them to pursue network projects with this higher risk profile. The drivers supporting the Registered Power Zones concept can be summarised as follows:
• To encourage DSOs to integrate appropriate technical development plans as part of their wider business innovation.
• To deploy new technologies, and encourage their wider application, where this enables dis-tributed generation to be integrated more effectively and efficiently, to help meet the gov-ernment’s targets for renewables and CHP.
• To signal to potential generators and other interested parties the DSOs’ development inten-tions or the network capabilities at a particular location.
2.4.2 Integrating DG in Denmark
The country with the largest share of DG on its electricity supply system is Denmark. Especially Western Denmark can be seen as a testing ground for implementing large amounts of DG into the distribution network as it has already reached a high percentage of this due to decades of promotion of wind turbines and medium and small-scale CHP in the Danish energy policy. Dan-ish energy policies have, as of 2001, led to the building of approximately 1600 MW of dispersed CHP production and approximately 1900 MW of wind turbines in Western Denmark (60% of the country consumption, with Eltra as TSO). About 50% of power production is now ‘bound production’, i.e. either dependent upon the amount of wind available or, for the local CHP plants, the demand for district heating. The majority of these distributed generation facilities are connected to voltage levels of 60 kV and lower, as can be seen from Figure 2.4 (Hindsberger, 2003).
Figure 2.4 Production capacity at each voltage level in the Western Part of Denmark
Compared with the values in Figure 2.4, the wind capacity has increased even further. By the end of 2002 there was a capacity of 2155 MW connected to 60 kV or below (another 160 MW, the Horns Rev offshore wind power park is connected to 150 kV). Together with the approxi-mately 1600 MW of small-scale CHP, the DG in Western Denmark can produce as much as the peak load of the area, which in 2002 was 3685 MW, while the minimum load of 1189 MW of-ten can be supplied by wind turbines alone.
The costs of network reinforcements, the so-called deep connection costs, have rapidly in-creased during the 1990s. In the period from 1992 to 2001 the extra investments made represent more than DKK 630 million (of which DKK 400 million is due to due wind power)13. This cor-responds to DKK 300,000 per MW for wind power and DKK 500,000 per MW for CHPs. As a comparison, the cost of building a wind turbine on land currently is in the order of DKK 6-7 million per MW (Hindsberger, 2003).
In many situations, operators have to reinforce the grid to enable the power supply, even though these reinforcements are of no benefit in terms of distributing energy to consumers. Wind tur-bines and local CHP plants have displaced central units, which are being decommissioned, as there is no longer any commercial basis for them. It means that the balancing units disappear in areas where the need for balancing capacity is growing. The balancing must then be effected by the local CHP plants and the wind turbines. Eltra, the Western Denmark TSO, is therefore work-ing on gettwork-ing these services from the DG operators through changes in the regulation, the re-quirements set-up for new units, and through support to R&D in technical solutions. From a transmission system operator’s point of view, it is critical that the earlier ‘passive’ production units are transformed into active elements so they can deliver the ancillary services required by the grid.
Small-scale production has priority access to the network in Denmark, and distribution compa-nies are obliged to connect it. The producers pay only shallow connection costs, i.e. the costs just to the nearest 10 kV connection point, even if grid reinforcement or the addition of another connection point is needed, with the distribution company paying the rest (i.e. costs are social-ised through the Use of System charges to the consumers). By 2001 this energy policy has re-sulted in approximately 50% of the electricity production in the Eltra region having priority ac-cess of this kind. Therefore, small-scale CHP and wind power cannot be regarded as secondary production.
13
At present, balancing a power system like the Danish one can only be done if it is connected to areas with other types of production. The large proportion of ‘bound’ production puts pressure on the transmission capacity within the Eltra area and on neighbouring areas. The flow towards transmission level causes problems with regard to regulating transformers and with regard to the voltage profiles in the distribution networks having lower voltages at the points of transforma-tion than the points of infeed of the wind power. Distributransforma-tion companies therefore often connect wind power at separate outlets, where consumption is not connected. This gives rise to more networks than needed for consumption only.
Excess power arising from bound production can be exported, provided that capacity is avail-able on the interconnections to Norway, Sweden and Germany. However, if the oversupply be-comes larger than available capacity, then there will be a critical power overflow. During a critical overflow, there is a risk of disturbances, and of a system breakdown (Jensen, 2002). As overflow situations may well become critical during the next few years, ways have to be found to balance the system by means of the following measures:
• closing down local CHP plants, • closing down wind turbines, • introducing flexible loads, • installing heat pumps.
At the moment, Eltra is also analysing the possibility of dispatching the local CHP plants. How-ever, the use of any of these measures will require changes in the taxation system.
Several international studies have presented ideas for the integration of distributed electricity production. For the Eltra electricity system in Denmark some principles have been identified by Nielsen (2002a) as part of a long-term solution:
• A control hierarchy consisting of a central control centre (at the TSO) and a number of re-gional control centres will be established. Each region consists of a number of local areas. Each local area will be connected to the transmission system via one 150/60 kV substation. An unambiguous operational responsibility must be defined for each local area.
• Prioritising of electricity from local DG (CHP/RES) plants should be cancelled so that these power plants can be operated in the same way as conventional power plants in accordance with price signals from the (day-ahead and real-time) market. This principle offers network access on equal terms for all producers and opens up for a better utilisation of the network. • The balance of reactive power within each local area must be kept within certain limits to be
defined in a new set of rules. There must be local responsibility for observing these rules and the control of local reactive resources (including capacitors and local CHP plants) must be local as well.
• New rules for measuring must provide all necessary data for the regional control centres and to the extent necessary for the TSO. Reliable information on the state of the system and data for accurate system analysis must be available at any time.
2.5 Future
networks
The previous section showed that integrating large shares of DG in existing networks may pre-sent problems in terms of network stability etc. This section looks at new ways of managing networks with high levels of DG. For that purpose two visions are described, the ‘active net-works’ and ‘Micro-grids’.